Extracting hydrocarbons from a subterranean formation involves flowing hydrocarbons from the formation to surface through a production well bore. In the early stages of production, the hydrocarbons are driven into the production well and flowed to surface by pressure within the formation. However, over time the formation pressure reduces until natural extraction can no longer be sustained, at which stage some form of artificial or assisted extraction is required. One common form of artificial extraction involves the injection of a fluid medium into the depleting formation through an injection well bore which extends from surface in order to displace the hydrocarbons from the formation. Conventionally, the fluid medium is aqueous and may be produced water or sea water or the like. Fluid injection in this manner may also be utilised as a form of matrix support in order to prevent collapse of the reservoir after the hydrocarbons have been removed.
Where water injection is utilised to displace hydrocarbons from the formation, or provide matrix support, it is important that the injection water is compatible with the formation chemistry and is substantially free from suspended or dissolved particles and colloidal and macromolecular matter. This is required to prevent or at least minimise plugging of the formation and associated wells, which occurs when precipitates or suspended particles or the like accumulate and block, or plug, fluid passageways. Such fluid passageways may include pores, fractures, cracks or the like in the hydrocarbon-bearing rock formation, or passageways defined by production and injection well bores. This plugging can significantly reduce hydrocarbon production and in severe cases can terminate production altogether.
In order to ensure that the injection fluid or water is substantially free from suspended or dissolved particles and the like, it is known in the art to treat the water prior to injection into the formation. Treatment normally includes a combination of chemical and mechanical or physical processes. For example, coagulants or flocculants may be added to the water to encourage flocculation where heavy particles or flocculus, known as “floc”, are formed. The floc may then be removed by sedimentation and/or by filtration whereby mechanical straining removes a proportion of the particles by trapping them in the filter medium. Conventional filtration apparatus for use in treating injection water to remove such particulate material include filtration or separation membranes, multimedia filters and the like.
With regards to plugging caused by precipitate formation and accumulation, this occurs when ionic species in the injection fluid or water combines or reacts with compatible ionic species in water present in the formation producing a precipitate or scale. For example, divalent sulphate anions in the injection water will combine with various cations which may be present in the formation water to form substantially insoluble precipitates. For example, the formation water may contain, among others: barium cations, which when combined with sulphate produces a barium-sulphate or barite precipitate; strontium cations resulting in the formation of a strontium-sulphate precipitate; or calcium cations resulting in the formation of a calcium-sulphate or anhydrite precipitate or scale. As noted above, these resultant precipitates are substantially insoluble, particularly barite, making any precipitate purging and removal/squeezing process extremely difficult, complicated and expensive.
Additionally, the presence of sulphate in the injection fluid or water provides a source of sulphur which thermophilic sulphate reducing bacteria (SRB) that may be present in the formation feed on, producing hydrogen-sulfide which causes souring of the well. Hydrogen-sulfide is extremely corrosive and specialised equipment must be used to accommodate the “sour” hydrocarbons, both at the extraction/production stage and at the processing stage. Using injection water with a high sulphate content can therefore sour an originally “sweet” well.
Various methods have been proposed to provide a preventative solution by removing the problematic, or precursor divalent ions from the injection water before injection into the formation. For example, prior art reference U.S. Pat. No. 4,723,603 discloses a process in which a feed water is treated to remove precursor ions by a process of reverse osmosis to produce a treated injection water product.
In offshore environments, a significant proportion of platform space is dedicated to fluid treatment systems, such as injection water treatment systems. This presents problems in view of the limited space available in these environments. Furthermore, known filtration or separation systems operate by creating pressure differentials across the filtration media, for example across membranes and the like, which typically involves the use of specialised plant equipment, such as pumping systems and fluid control equipment including valves and the like. Such plant equipment requires dedicated space and an energy source and is susceptible to mechanical failure. These problems are also true for any separation system, including those outside the mineral extraction industries, such as desalination for generating potable water, power generation and the like.